Distribution transformers are parts of the power system infrastructure. The power system infrastructure includes power lines, transformers and other devices for power generation, power transmission, and power delivery. A power source generates power, which is transmitted along high voltage (HV) power lines for long distances. Typical voltages found on HV transmission lines range from 69 kilovolts (kV) to in excess of 800 kV. The power signals are stepped down to medium voltage (MV) power signals at regional substation transformers. MV power lines carry power signals through neighborhoods and populated areas. Typical voltages found on MV power lines power can be from about 1000 V to about 100 kV. The MV voltages are stepped down further to low voltage (LV) levels by distribution transformers. A low voltage subnet (as used herein) comprises the LV power lines connected to the distribution transformer and that carry power to the customer premises. The LV power lines have voltages ranging from about 100 V to about 600 V, and in the United States, typically about 120 volts (referenced to ground).
In the United States local distribution transformers typically feed anywhere from one to ten homes, depending upon the concentration of the customer premises in a particular area. A power distribution system for a given area may include many distribution transformers and thousands of distribution transformers may be located within a city or region. Thus, distribution transformers represent a significant capital investment. Some utilities spend a significant percentage of total distribution capital spending in one year on new distribution transformers.
The total cost of owning a distribution transformer (hereinafter “owning cost) to a utility includes the cost of the transformer, (e.g., purchase price, installation cost, residual end of life cost, interest, depreciation, taxes), the cost of energy consumed by transformer losses, and the cost of the system capacity required to accommodate such losses. In the past the useful life of a distribution transformer has been approximately twenty years. Consequently, even small decreases in efficiency may result in power losses (to the utility) that result in a substantial financial impact (e.g., owning cost) when such losses occur over many years of operation. In addition, such losses cause the utility to generate more power than otherwise would be necessary, thereby negatively impacting the environment. When such losses occur for many transformers over many years, a utility also may make capital expenditures to increase system capacity that may not have been necessary but for the inefficiencies. Accordingly, inefficient distribution transformers may result in increased costs associated with the cost of power losses and capital expenditures as well as negatively impact the environment.
On challenge to utilities is that utilities cannot readily identify inefficient transformers. The Distribution Systems Testing, Application, and Research (DSTAR) utility consortium commissioned the development of the Transformer Owning Cost Software (TOCS) tool for analyzing and comparing the total owning cost of distribution transformers. TOCS is a tool for performing detailed analysis on different distribution transformer designs and loading characteristics. A batch analysis functionality within TOCS enables users to run multiple loading scenarios against a set of transformers and predict an estimated annualized owning cost. However, this software provides an estimate. Conventionally there has been no way of specifically determining the efficiency of an installed distribution transformer on a continuous ongoing basis during normal operation. In the past a utility crew may have measured the efficiency of a distribution transformer during a routine maintenance procedure. However, sending a crew to measure the efficiency of the multitude of distribution transformers residing in a large geographical area, such as a city, county, or state, would be cost prohibitive. In addition, measurements taken by a crew provide a “snap shot” of the transformer's efficiency under the then present conditions (e.g., at that temperature and with the existing load). Consequently, if the transformer's efficiency were to change (e.g., due to aging, change in temperature, change in load, etc.), the snap shot provided by a crew may be inaccurate, or worse, may have been misleading. Accordingly, there is a need for determining the efficiency of an operating distribution transformer in a cost effective, reliable, and accurate manner.